The invention relates to a method for improving the injectivity of a well for water or gas injection into an underground hydrocarbon formation. More particularly, the invention method injects a microemulsion of surfactant and solvent into the near wellbore area to lower residual oil saturation.
Residual saturation of oil in the near wellbore area of an injection well can severely limit the injectivity of water and other fluids with limited oil solubility. This permeability limit is the result of the oil in the pore spaces controlling any mobile fluid in the interstitial pores. One may also view the residual oil as droplets trapped in the larger areas of the pore. When these droplets start to flow because of a pressure differential, they plug the outlet of the pore space much like the ball in a check valve. These restrictions on flow greatly increase the cost of water injection in secondary recovery and also limit the rate at which oil can be produced from some reservoirs. Tertiary recovery schemes are also limited by oil or oil products in the near wellbore area.
The industry has attempted to solve injectivity problems with the injection of surfactant slugs. U.S. Pat. No. 4,886,120 discloses the use of a surfactant slug to improve the water injectivity of a well, wherein the surfactant has the formula: EQU RO(C.sub.3 H.sub.6 O).sub.7 (C.sub.2 H.sub.4 O).sub.2 YX,
wherein R is a mixture of alkyl groups containing from 12 to 15 carbon atoms, Y is a sulfate group, and X is a monovalent cation. U.S. Pat. No. 4,690,217 discloses the use of a similar propoxylated, ethoxylated surfactant to increase water injectivity into a formation.
U.S. Pat. Nos. 4,216,098; 4,293,428; 4,406,798; 4,738,789 and numerous others disclose the use of alkoxylated surfactants for tertiary oil recovery by injection in surfactant slugs.
A field test of surfactant injection to decrease oil saturation around a well and increase injectivity is discussed in Dymond, P. F. et al., "Magnus Field: Surfactant Stimulation of Water-Injection Wells," SPE Reservoir Engineering, Feb. 1988, pp 165-174. The systems disclosed as tested in the laboratory or in the field consisted of polyalkylene sulfonate mixed with alkylphenol alkoxy alcohol and C.sub.4 and C.sub.5 aliphatic alcohols for the cold test at 20.degree. C., and alkyl aromatic alkoxysulfate and C.sub.5 aliphatic alcohol for the hot case of 105.degree. C., slightly lower than reservoir temperature.
SPE Paper 12599, Martin, F. D., "Injectivity Improvement in the Grayburg Formation at a Waterflood in Lea County, NM," presented at the 1984 Permian Basin Oil and Gas Recovery Conference in Midland, Texas, Mar. 8-9, 1984, discusses two field tests of a surfactant solution alone, and an aromatic solvent followed by a surfactant solution to increase water injectivity in a New Mexico well. The injected surfactant was a phosphate ester in each test and the solvent was aromatic naphtha.